Coiled tubing is widely used in the oil and gas industry for completion, production and workover operations. Some of the oilfield operations in which such tubing is used are acidizing, cementing, corrosion control, and downhole nitrogen application. In such operations, the coil tubing is used to transport fluids from the surface down into the well to a predetermined location.
The coil tubing is spooled onto a large reel that is rotatably mounted on a truck. The truck transports the coil tubing on the reel to the field for the injection of fluids into the well. The coil tubing is unwound or played from the reel and is passed into the well through an injector head. The injector head includes a driving mechanism for raising and lowering the coil tubing in the well. The driving mechanism on the injector head forces or drives the coil tubing down into the well and later pulls and lifts the coil tubing from the well to be wound back onto the reel.
In service, the coil tubing may remain suspended in the well for continuous use, and it may extend from the surface to the bottom of the well or to an intermediate point between the surface and the well bottom. The coil tubing may also be temporarily suspended into the well for the duration of a particular operation during which the tubing is often raised and lowered to various levels in the well. Upon completion of the operation, the tubing is spooled back onto the reel to be used for another operation or possibly to be transported to a different location.
Typical fluids that might be injected into the well include acid, corrosion inhibitors, and nitrogen. Such fluids are pumped downhole through the interior of the coil tubing and into the well to perform the particular required operation. The free end of the tubing is connected at the surface by a rotary connection to a pump which in turn communicates with a tank storing the appropriate fluid for the particular operation. The other end of the tubing is forced downhole into the well to allow the injection of the fluids at a predetermined depth.
Historically, in wells having a relatively shallow depth, the coil tubing was straight wall tubing, i.e., tubing having a common inner and outer diameter throughout its length. Many of today's wells now have a depth of 20,000 feet, and it has become desirable to have even deeper wells in order to reach deeper lying hydrocarbon deposits. Thus, it has become necessary to suspend coil tubing 20,000 feet or more downhole. As the length of the straight wall tubing approximates 20,000 feet, the weight of the tubing suspended in the well together with the force required to lift the tubing string in the well may exceed the yield load capacity and the ultimate load capacity of the tubing causing the tubing to fail. For example, the weight of steel tubing, even without a pull force, having a minimum yield of 70,000 pounds per square inch, a minimum ultimate strength of 80,000 pounds per square inch, a nominal outside diameter of 1.25 inches, a nominal wall thickness of 0.109 inches and a density of 490 pounds per cubic foot exceeds its yield load capacity of 27,370 pounds when the total length of the suspended tubing exceeds 20,700 feet. Furthermore, the weight of such tubing exceeds its ultimate load capacity of 31,280 pounds when the total length of the suspended tubing exceeds 23,600 feet. Although it might seem obvious to merely provide a thicker and heavier wall tubing to provide additional yield and load capacities, the thicker and heavier wall only further increases the weight of the tubing and thus does not offer a solution.
The industry's response to this problem is to seek a reduction in the overall weight of the tubing string extending into the well at these great depths. One approach to the reduction of tubing weight is to use a thinner and lighter wall tubing at the lower depths in the well. For example, to reduce tubing weight, thicker or heavier wall tubing is used in the upper portion of the tubing string, as for example the first 3,000 to 4,000 feet of tubing string, and a thinner and lighter wall tubing is used for the lower portion of the tubing string, as for example the lower 15,000 to 16,000 feet. Thus, the yield and ultimate load capacities of the coil tubing are greater in the upper portion of the string where greater yield and ultimate load capacities are required to support the suspended tubing and lower in the lower portion thereof where smaller yield and ultimate load capacities are required since the lower portion supports less tubing string. At the same time, the reduction in the wall thickness results in a reduction in the weight of the suspended tubing.
A tubing string with dissimilar wall thicknesses is formed by welding individual tubing sections formed from tubing strips in ascending order with the thickest wall tubing section at the top, and the thinnest wall tubing section at the bottom. Thus, when the tubing string is lowered into the well, the lowermost tubing section with the thinnest wall is below the tubing section with the next greater wall thickness and so on until the uppermost tubing section has the largest wall thickness whereby the lower tubing sections are thinner and lighter and the upper tubing sections are thicker, stronger and heavier. Each tubing section in the tubing string is designed to withstand the tensile stresses caused by the weight of that portion of the tubing string suspended below.
Because the steel mills are limited by current technology to producing steel strips having a length of approximately 2,000 feet, it becomes necessary to attach multiple sections of coil tubing together to produce a tubing string that will extend into wells having a depth of over several thousand feet. In order to achieve tubing strings such as those which must extend up to 20,000 feet into the well, multiple lengths of tubing sections are welded together. Accordingly, the tubing string is formed by butt welding in series a plurality of tubing sections. Where adjacent tubing sections have a common inner and outer diameter and thus wall thickness, a strong weld is achieved. However, as straight wall tubing has been replaced with a tubing string having tubing sections of dissimilar wall thicknesses the butt-welding of adjacent tubing sections has produced an inferior weld.
The circumferential joint welding process is normally applied to tubular members of approximately equal cross section. The various input parameters in the welding process, such as heat, speed and amount of filler material, are directly related to the thickness of the tubular wall. Problems are encountered in butt-welding tubing sections having dissimilar wall thicknesses because different input parameters are required. Thus, the weld parameters must be compromised to accommodate the dissimilar wall thicknesses. It is well-known that welding two metal sections having different wall thicknesses creates an inferior weld.
In butt-welding two tubing sections of different wall thicknesses to form a tubing string, the outside diameter of the two tubing sections is maintained constant, i.e. they have a common outer diameter. The inside diameter of the two tubing sections, however, is varied to increase the inner diameter of the lower section and to create a thinner tubular wall while the outer diameter is held the same.
In welding a thicker wall tubing to a thinner wall tubing, a step joint is created because the inner diameter of the thicker wall tubing is less than the inner diameter of the thinner wall tubing. This step joint is contrasted to the smooth joint which is formed in butt-welding two adjacent straight wall tubing sections that have the same thickness.
Initially, industry hand welded the step joint, but because the welding resulted in inferior welds, the industry has gone to using an automatic, computerized welding machine. Such automatic welding machines are very expensive; and, even using the automatic welding machines, the compromised welding parameters, due to the varying inside diameters of the step joint prevent achieving a weld comparable to the weld between two straight wall tubing sections.
Upon completion of the butt-welding of two adjacent tubing sections, the joint is given a post heat treatment for metallurgical reasons such as for stress relieving the weld. Such post heat treatment includes applying a wraparound heating coil to the joint and heating the joint to a predetermined temperature for a predetermined period of time. The post heat treatment parameters, which define the proper stress-relieving treatment for the welded joint and include factors such as temperature and time, are dependent upon the wall thicknesses of the joined tubing sections. Similarly, the parameters which define the welding process itself are dependent upon the wall thicknesses of the tubing sections. Heat treatment of tubular walls with a common thickness achieves satisfactory results. However, step joints require heat treatment of dissimilar wall thicknesses theregy causing the post heat treatment to be less than satisfactory. Because the tubular walls have dissimilar thicknesses, each thickness dictates a different set of heat treatment parameters. Thus, where dissimilar wall thicknesses must be heat treated, the parameters for the post heat treatment must be compromised, and the post heat treatment is inferior.
FIG. 2 of the drawings illustrates the prior art step joint. Upper, intermediate and lower tubing sections A, B and C, respectively, are shown butt-welded in series. Although other tubing sections may be welded above and below upper and lower tubing sections A and C, such sections have not been shown for purpose of simplicity. Upper and intermediate sections A and B are shown welded at S1, and intermediate and lower tubing sections B and C are shown welded at S2. The outside diameters of tubing sections A, B and C are all common, i.e., equal and uniform. However, the inside diameters and wall thicknesses of each tubing section are different with the inside diameter increasing and the wall thickness decreasing.
As is clearly shown in FIG. 2 illustrating the prior art, the butt-welds at S1 and S2 create step joints I1 and I2 which are caused by the stepwise, abrupt and noncontinuous change of wall thickness and internal diameter. Such step joints are structurally weak and inferior. Thus, the tubing string becomes susceptible to failure at these step joints when forces are applied thereon due to the weight of the suspended tubing string, or when other mechanical and hydraulic forces are applied across the joints.
Step joints cause other serious problems. Since the tubing string must be coiled and uncoiled from the spool, the tubing is subjected to bending moments. It is well-known that upon applying the same bending moment to a stronger member connected to a weaker member, the weaker member will collapse or fail. Thus, as the tubing string is coiled and uncoiled from the spool, bending moments are applied across the step joints in the tubing string such that the mechanical forces due to the bending moments cause the thinner wall tubing to fail.
A further disadvantage of step joints is the application of hydraulic forces to the tubing by the mechanical device on the injector head which raises and lowers the tubing string in the well. This device uses back-to-back hydraulically powered chains having cleats that engage the tubing as the tubing passes between the chains. The hydraulic pressure of the chains can be adjusted to place only that pressure on the tubing which is required to adequately engage the tubing and lift the tubing from the well without the tubing slipping between the chains. However, the pressure on the tubing cannot be so great as to overly compress and thereby collapse the tubing. Thus, the device is designed for adjusting the hydraulic pressure on the chains based upon the length of the tubing in the well and the size and strength of the tubing disposed between the chains. As the tubing string is raised from the well, the weight of the tubing string is reduced since less tubing is suspended; and, therefore, the hydraulic pressure can be reduced. Further, as the wall thickness of the tubing is reduced, the resistance of the tubing to collapse is reduced, and the hydraulic pressure should also be reduced. Thus, as the tubing string is pulled from the well, the hydraulic pressure on the chains is reduced because of the reduced weight of the tubing string and because of the reduced compressive strength of the thinner wall tubing.
The step joint, however, creates an immediate transition from a thick wall tubing to a thin wall tubing. Since the chains engage the tubing over a substantial length as the tubing passes through the device, adjustment of the hydraulic loading for dissimilar sizes of tubing is not possible. Thus, the thin wall tubing is subjected to the same hydraulic load as the thick wall tubing. Under such circumstances, the thin wall tubing may fail under the undue hydraulic pressure.
The structural weaknesses caused by the step joints in the tubing string create other problems. The raising and lowering of the tubing string within the well creates a "yo-yo" effect because of the natural elasticity of the steel tubing string. This "yo-yo" effect places heavy tensile stresses on the string and thus the tubing string may snap at the weak step joints.
Further, varying inernal and external pressures are placed on the tubing string as it is raised and lowered in the well. The tubing string is constantly under both internal and external pressures due to the fluids passing down the string to the bottom of the well and by the well fluids surrounding the tubing string which create a static head that compresses the tubing string. Such head pressures are greatest near the bottom of the well. Where the differential pressure across the tubing is great, and particularly when applied to the step joint, the tubing string can fail at the joint. Further, as the tubing string is raised and lowered in the well, the tubing string encounters both internal and external pressure changes which when applied to the weak step joint, can cause the step joint to break.
The injection fluids passing through the tubing string are under pressure. As the injection fluids travel across a step joint, turbulence is created because the inner tubular wall is unsmooth. Such turbulence tends to cause the fluids to eat away at the wall of the tubing just past the step joint and may cause the tubing to fail. This has become more critical as better grades of tubing have become available since better tubing has permitted an increase of the pressure of injection fluids. Now it is possible to use pressures in the order of magnitude of 10,000 PSI. As this pressure is increased, the turbulence caused by step joints is further increased thereby enhancing the problem.
Needless to say, if the tubing string fails and a portion thereof drops down into the well, a fishing operation is required to retrieve the broken tubing string out of the well. Such fishing operations are very expensive and time consuming.
Although these deficiencies of the prior art are particularly acute when the tubing string exceeds a length of 20,000 feet, it may be desirable to reduce the weight of the tubing string in more shallow wells, such as wells of approximately 10,000 feet in depth. Even at such depths, the mechanical device raising and lowering the tubing string must still place substantial pressure on the tubing to raise and lower the string. Even a tubing string of approximately 10,000 feet in length has substantial weight whereby the hydraulic forces applied by the mechanical device in raising and lowering the string could break the tubing. If tubing of greater strength is used to overcome the problem, such tubing may be too stiff and not have sufficient bending capability to coil the tubing onto the spool. Thus, it may be advantageous to use lighter tubing strings even in a more shallow well by using a tubing string comprised of tubing sections with dissimilar wall thicknesses.
There are other reasons for using thin wall tubing together with thick wall tubing besides weight reduction. Thin wall tubing allows the use of certain downhole tools and also permits the custom design of the tubing string for a particular well where it is anticipated that certain pressures will be encountered by the tubing string at particular depths. For example in some cases, the pressure differential between the internal and external pressures of the tubing string is not as great at the bottom of the well as it is at the surface and thus it may be advantageous to have thin wall tubing making up the lower portion of the string where less strength is required.
The present invention overcomes the aforementioned deficiencies of the prior art by providing a coil tubing string that includes tubing sections with varying wall thicknesses to achieve weight reduction and also eliminates the structurally weak step joint and inferior weld. The tubing string of the present invention includes continuous inner and outer walls with smooth joints between adjacent tubing sections. Such smooth joints are accomplished by using tapered tubing sections having a tapering internal wall with an inner diameter that increases in a progressive, continuous, and smooth fashion from one end to the other. Each end of the tapered section has a wall thickness equal in inner and outer dimension to that of the adjacent tubing section such that step joints are eliminated. Thus, a smooth wall is formed throughout the tubing string while achieving an ascending magnitude of strength from the lower end of the string to the surface. No stepwise, abrupt or noncontinuous changes of wall thickness or strength occur. Since the strength and structural integrity of the smooth joints are enhanced by the common wall thicknesses at the welds and the transition from one wall thickness to another occurs over a substantial length, structural failures are greatly reduced.
Various tapered conduits have been used for other applications in the prior art. For example, U.S. Pat. No. 3,152,458 discloses a drill pipe, usually 30 feet in length, having a tapered portion extending between a lower heavy wall portion connected to lower heavy drill collars and an upper heavy wall portion connected to the drill pipe string extending to the surface.
Other objects and advantages of the present invention appear from the following description.